1. Field of the Invention
The present invention generally relates to improvements in methods by which coal fired boilers, especially boilers in existing electric power generation plants, can operate to economically reduce the emissions of nitrogen oxides (NOx) by means of Selective Non-Catalytic Reduction (SNCR), which is effected by injection of urea or ammonia-water droplets of varying size into a high temperature, post combustion zone in the boilers, either by-itself, or in combination with the reduction of sulfur dioxide (SO2) by the co-injection of reducing agents, such as lime or limestone in the injection lances utilized for the SNCR process.
2. Description of Relevant Art
U.S. Pat. No. 6,048,510, Dated: Apr. 11, 2000, U.S. Pat. No. 6,453,830 B1, Dated: Sep. 24, 2002, and U.S. Pat. No. 6,722,295 B2, Dated: Apr. 20, 2004 are hereby incorporated by reference in their entireties. When Congress enacted the Clean Air Act in the 1970's existing coal fired power plants where exempt from new emission controls under a “grandfather” clause based on the assumption that they would soon be shut down. Only “routine maintenance” was allowed, which not surprisingly initiated decades long legal challenges as to the meaning of “routine maintenance”. The effect of this was that few, if any, new coal fired power plants that would have to meet stringent emission standards were erected.
There currently exists a problem which is faced by many existing domestic and overseas power plants whose size and age precludes economic retrofit with very high NOx reduction processes, such as Selective Catalytic Reduction (SCR) and very high SO2 reduction processes, such as wet or dry scrubber, both of which have very high installed capital costs. By way of example, according to the Department of Energy (DOE), this category of boilers applies to 66% of U.S. coal fired power plants. The boilers are under 300 MW in size and on average 15 years old. To allow these boilers to continue operating in the face of increasingly stringent SO2 and NOx emission standards, the U.S. Environmental Protection Agency (EPA) has introduced trading in emission credits, whereby an emitter of NOx and SO2 whose emissions exceed the annual regulatory specified emission “allowances” can purchase in the open market emission credits from an emitter whose emission are below the standards.
Instead as power demand increased by the 1990's combined with utility deregulation, non-utility investors, called merchant power developers, began to erect natural gas fired, combined gas turbine-steam turbine power plants as well as gas turbine peaking plants. They were much lower in capital cost, could be erected rapidly and natural gas was only a few dollars per million Btu. Equally important was the negligible emissions of SO2 from the natural gas fired power plants and their very low emissions of NOx. As a result, high emission coal fired power plants could purchase emission “credits” on the open market at low cost, with SO2 available at under $200 per ton and NOx for under $1,000 per ton.
Apparently overlooked by merchant power developers was that relying on natural gas, a relatively scarce commodity in the U.S., would inevitably lead to higher prices. This indeed occurred during the California electricity crisis of 1999-2000, with the price of natural gas spiking to $10/MMBtu from its historical $2/Mmbtu. At $10/MMBtu, the fuel alone for a very high, 50% efficient gas-fired combined cycle plant is about $70/MW, plus the substantial amortization cost of new power plants as well as their operating costs. This compares to the historical nominal $20/MW off-peak power and about double that for on-peak power prices from old coal fired power plants. While peaking gas turbines could operate during hours of peak demand, such as during hot summer days when prices spike into the $100's/MW, combined cycle gas fired plants cannot be cycled daily to and from shutdown. As the price of natural gas remained at ever increasing prices, peaking at $15/MMBtu in late 2005, even some of the largest owners of the new gas fired power plants were forced into bankruptcy.
Coal fired power plants were beneficiaries of reduced output from gas fired power plants. However, in 2003 EPA introduced more stringent NOx and SO2 emission standards. The new ceiling on NOx emissions is 0.15 lb/MMBtu. As a result, the price of NOx emission spiked to $6,000 per ton in 2003, and it has remained in the $2000 to $3000/per ton range until the end of 2006, and then decreasing to about $1000. Also, SO2 emission credits, which had remained at near historic levels of less than $200/ton, in part due to the increased use of low sulfur coal in the East and low sulfur Western coal shipped to the Mid-West, began to increase to the $600 to $700 per ton range in 2004 as the price of these coals began to increase. By late 2005, the price of SO2 spiked to $1,600 per ton, presumably in anticipation of more stringent EPA emission standards. In 2006 it has decreased to the $500 range possibly to the large number of banked SO2 credits coming on the market. One lesson to a power plant operator is to assure that these sudden and wide market fluctuations do not result in operating losses.
One option for existing coal fired power plants is to add SO2 stack scrubbers and NOx Selective Catalytic Reduction (SCR) systems that can meet the current stringent standards. While activity in this area has increased, it is not a solution to many coal fired power plants because their high (at least $70/kW each) capital cost carries the risk adding long-term fixed costs to old power plants, which would make these plants unprofitable if electricity prices were to decline during the amortized life of this pollution control equipment.
U.S. Pat. Nos. 6,048,510 and 6,722,295 (which are hereby incorporated by reference in their entireties) were utilized in practicing the above patents. U.S. Pat. No. 6,048,510 discloses methods to reduce NOx in the post-combustion zone of coal fired utility boilers by injecting droplets of varying size, consisting of urea dissolved in water, at the outer edge of a gas zone and dispersing them throughout the gas zone where the gas temperatures are in the range of 1700° F. to 2100° F. that is conducive to NOx reduction. U.S. Pat. No. 6,722,295 discloses a method of using the same equipment as in U.S. Pat. No. 6,048,510 patent and adding to the water-urea solution, very fine lime or limestone particles that are dispersed in the droplets for the purpose of simultaneously reducing both NOx and SO2.
The research and development that led to the NOx and SO2 patents (U.S. Pat. Nos. 6,048,510 and 6,722,295, respectively,) was implemented primarily during testing in the post-combustion zone of a 20 MMBtu/hour coal combustor-package boiler facility shown schematically in FIG. 1 in each of the two patents, as described in detail in the patents. The patents summarize test results in the boiler in which peak SO2 reductions in the 80% range were obtained by injection of droplets of lime or finely ground limestone dispersed in water. Also, NOx reductions of up to 80% were measured in the boiler with droplets of ammonia-water solutions and somewhat lesser amounts with urea-water solutions.